The present invention relates to the field of processes for the deacidification of a gaseous effluent. The invention advantageously applies to the treatment of gases of industrial origin and natural gas.
Absorption processes involving an aqueous solution of amines are commonly used for removing acidic compounds (especially CO2, H2S, COS, CS2, SO2 and mercaptans) present in a gas. The gas is deacidified by placing it in contact with the absorbent solution, and the absorbent solution is then thermally regenerated. For example, document U.S. Pat. No. 6,852,144 describes a method for removing acidic compounds from hydrocarbons. The method uses a water-N-methyldiethanolamine or water-triethanolamine absorbent solution containing a high proportion of a compound belonging to the following group: piperazine and/or methylpiperazine and/or morpholine.
One limitation of the absorbent solutions commonly used in deacidification applications is an insufficient absorption selectivity for H2S relative to CO2. Specifically, in certain cases of deacidification of natural gas, selective removal of H2S while limiting to the maximum the absorption of CO2 is sought. This constraint is particularly important for gases to be treated already containing a CO2 content that is less than or equal to the desired specification. Maximum H2S absorption capacity with maximum absorption selectivity for H2S with respect to CO2 is then sought. This selectivity makes it possible to maximize the amount of treated gas and to recover at the regenerator outlet an acidic gas having the highest possible concentration of H2S, which limits the size of the sulfur chain units downstream of the treatment and ensures better functioning. In certain cases, an H2S enrichment unit is necessary to concentrate with H2S the acidic gas. In this case, the most selective amine is also sought. Tertiary amines, such as N-methyldiethanolamine, or hindered amines which have slow kinetics of reaction with CO2, are commonly used, but have selectivities limited to high H2S charge levels.
Another limitation of the absorbent solutions commonly used in total deacidification applications is excessively slow CO2 or COS uptake kinetics. In the case where the desired specifications on CO2 or COS are very rigorous, the fastest possible reaction kinetics are sought so as to reduce the height of the absorption column, this equipment under pressure, typically at between 20 and 90 bar, representing a sizeable part of the investment costs of the process.
Whether maximum CO2 and COS uptake kinetics in a total deacidification application or minimum CO2 uptake kinetics in a selective application are sought, it is always desired to use an absorbent solution having the highest possible cyclic capacity. This cyclic capacity, noted Δα, corresponds to the difference in charge rate (α denoting the number of moles of acidic compounds absorbed nacidic gas per kilogram of absorbent solution) between the absorbent solution feeding the absorption column and the absorbent solution withdrawn at the bottom of said column. Specifically, the greater the cyclic capacity of the absorbent solution, the lower the flow rate of absorbent solution needed to deacidify the gas to be treated. In gas treatment processes, reducing the flow rate of absorbent solution also has a strong impact on the reduction of the investments, especially as regards the dimensioning of the absorption column.
Another fundamental aspect of operations for treating industrial gases or fumes with solvent remains the regeneration of the separating agent. Depending on the type of absorption (physical and/or chemical), regeneration by pressure reduction and/or by distillation and/or by entrainment with a vaporized gas known as a “stripping gas” is generally envisioned.
Another limitation of the absorbent solutions commonly used at the present time is an excessively high energy consumption necessary for regenerating the solvent. This is particularly true in the case where the partial pressure of the acidic gases is low. For example, for an aqueous solution of 2-aminoethanol (or monoethanolamine or ethanolamine or MEA) at 30% by weight used for the post-combustion uptake of CO2 in power station fumes, where the partial pressure of CO2 is of the order of 0.12 bar, the regeneration energy represents about 3.7 GJ per ton of CO2 taken up. Such an energy consumption represents a considerable operating cost for the CO2 uptake process.
It is well known to those skilled in the art that the energy required for regeneration by distillation of a solution of amine can be broken down into three different posts: the energy required to heat the solvent between the top and the bottom of the regenerator, the energy required to lower the partial pressure of acidic gas in the regenerator by vaporization of a stripping gas, and finally the energy required to break the chemical bond between the amine and CO2.
These first two posts are inversely proportional to the flow rates of absorbent solution that it is necessary to circulate in a unit in order to achieve a given specification. To reduce the energy consumption associated with the regeneration of the solvent, it is thus once again preferable to maximize the cyclic capacity of the solvent.
It is difficult to find compounds, or a family of compounds, that enable the various deacidification processes to function at reduced operating costs (including the regeneration energy) and investment costs (including the cost of the absorption column).
It is well known to those skilled in the art that tertiary amines or secondary amines with severe steric hindrance have slower CO2 uptake kinetics than sparingly hindered primary or secondary amines. On the other hand, tertiary or secondary amines with severe steric hindrance have instantaneous H2S uptake kinetics, which makes it possible to achieve a selective removal of H2S based on different kinetic performance qualities.
Among the applications of secondary amines with severe steric hindrance, document U.S. Pat. No. 4,405,581 describes a process for the selective absorption of sulfureous gases with an absorber containing secondary monoamines bearing severe steric hindrance, at least one of the substituents of which is a hydroxyalkyl group.
Document U.S. Pat. No. 4,405,811 describes a process for the selective removal of H2S in gases containing H2S and CO2 with an absorber containing tertiary monoamines bearing severe steric hindrance, at least one of the substituents of which is a hydroxyalkyl group.